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The Future of Hydrogen Chapter 6: Policies to boost momentum in key value chains 2. Existing gas infrastructure: Tapping into dependable demand Some 3 million km of natural gas transmission pipeline are in operation around the world today, and even greater lengths of distribution pipeline. These pipelines have near-term strategic value for hydrogen scale-up (Chapter 3). With only modest additional investment in infrastructure or end-use equipment, they would be able to transport the output of new hydrogen production facilities at low marginal costs, reducing the cost of supplying low-carbon hydrogen. Before 2030 governments will need to take important strategic decisions about the long-term future of natural gas and gas pipelines in order to ensure a smooth transition towards full conversion or, potentially, away from gas grid utilisation altogether. These decisions will confront all gas networks at some point if they are to reduce emissions significantly (including fugitive emissions) because there is no attractive low-carbon alternative. They will have knock- on implications for the investment needs of the electricity grid. Above a blended share of hydrogen of about 20%, the costs of modifying end-user equipment and the grid itself are only likely to be justified by a wholesale switch to 100% hydrogen. The two main ways to use hydrogen in the gas grid – blending hydrogen with natural gas, and converting the grid to 100% hydrogen – are distinct and treated independently in the following discussion. Blending hydrogen It is possible to blend small shares of hydrogen in existing natural gas systems with only minor changes to infrastructure, equipment and most end-user appliances, if changes are needed at all. Some new investment in hydrogen injection facilities would be needed, but in general blending at a safe level offers a relatively quick and easy way to transmit hydrogen supplies to end users, as long as hydrogen production is well-located near the gas transmission or distribution network. As described in Chapter5, several projects around the world are already demonstrating hydrogen blending in the gas grid for use in buildings, and more are planned on a larger scale. Among the larger proposed projects for coming years are electrolysers of 100 MW to 250 MW in Europe and North America that would run on wind or hydro power and inject tens of thousands of tonnes of hydrogen per year into the gas network. There are also proposed projects for blending hydrogen from natural gas with CCUS in Europe, including plans in North West England to inject around 0.6 MtH2/yr into the gas grid and to supply hydrogen to chemical plants by 2030, thus linking the gas grid and an industrial cluster. If these projects, and the H21 North of England project, go ahead, a sizeable and dependable hydrogen demand of over 2 MtH2/yr to could be created by 2030. If hydrogen were blended into all natural gas use in the European Union at just 5% by volume, this would boost low-carbon hydrogen demand by 2.5MtH2/yr. If this were supplied by electrolysers then it would require almost 25 GW of water electrolysis capacity. With cumulative installed capacity since 2000 standing at under 1 GW, this would amount to a significant scale- up, promoting efficiency improvements and capital cost reductions of up to one third. The capital investment for 25 GW of electrolyser capacity could be around USD 20 billion, plus an additional investment of over USD 3 billion for injection facilities (FCH JU, 2017). If the hydrogen were sourced from CCUS-equipped facilities instead, costs would likewise be expected to decline (not least because of the benefits that economies of scale bring to CO2 transport and storage), but less steeply. PAGE | 182 IEA. All rights reserved.PDF Image | The Future of Hydrogen 2019
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